In general terms, an oil well pumping system begins with an above-ground pumping unit, which creates the up and down pumping action that moves the oil (or other substance being pumped) out of the ground and into a flow line, from which the oil is taken to a storage tank or other such structure.
Below ground, a shaft or “wellbore” is lined with piping known as “casing.” Into the casing is inserted piping known as “tubing.” A sucker rod, which is ultimately, indirectly coupled at its north end to the above-ground pumping unit is inserted into the tubing. The sucker rod is coupled at its south end indirectly to the subsurface oil pump itself, which is also located within the tubing, which is sealed at its base to the tubing. The sucker rod couples to the oil pump at a coupling known as a 3-wing cage. The subsurface oil pump has a number of basic components, including a barrel and a plunger. The plunger operates within the barrel, and the barrel, in turn, is positioned within the tubing. The north end of the plunger is typically connected to a valve rod or hollow valve rod, which moves up and down to actuate the pump plunger. The valve rod or hollow valve rod typically passes through a valve rod guide.
Beginning at the south end, subsurface oil pumps generally include a standing valve, which has a ball therein, the purpose of which is to regulate the passage of oil (or other substance being pumped) from downhole into the pump, allowing the pumped matter to be moved northward out of the system and into the flow line, while preventing the pumped matter from dropping back southward into the hole. Oil is permitted to pass through the standing valve and into the pump by the movement of the ball off of its seat, and oil is prevented from dropping back into the hole by the seating of the ball.
North of the standing valve, coupled to the sucker rod, is a traveling valve. The purpose of a conventional traveling valve is to regulate the passage of oil from within the pump northward in the direction of the flow line, while preventing the pumped oil from slipping back down in the direction of the standing valve and hole.
In use, oil is pumped from a hole through a series of “downstrokes” and “upstrokes” of the oil pump, wherein these motions are imparted by the above-ground pumping unit. During the upstroke, formation pressure causes the ball in the standing valve to move upward, allowing the oil to pass through the standing valve and into the barrel of the oil pump. This oil will be held in place between the standing valve and the traveling valve. In the conventional traveling valve, the ball is located in the seated position. It is held there by the pressure from the oil that has been previously pumped. The oil located above the traveling valve is moved northward in the direction of the 3-wing cage at the end of the oil pump.
During the downstroke, the ball in the conventional traveling valve unseats, permitting the oil that has passed through the standing valve to pass therethrough. Also during the downstroke, the ball in the standing valve seats, preventing the pumped oil from slipping back down into the hole.
The process repeats itself again and again, with oil essentially being moved in stages from the hole, to above the standing valve and in the oil pump, to above the traveling valve and out of the oil pump. As the oil pump fills, the oil passes through the 3-wing cage and into the tubing. As the tubing is filled, the oil passes into the flow line, from which the oil is taken to a storage tank or other such structure.
In a tubing pump, the barrel assembly is coupled to and becomes a part of the well tubing at the bottom of the well. Tubing pumps are typically designed for pumping relatively large volumes of fluid, as compared with smaller pumps, such as insert pumps. With a tubing pump, the well tubing must be removed from the well in order to service the pump barrel. Alternatively, with an insert pump, the barrel assembly is a separate component from the well tubing. With an insert pump, the complete pump is attached to the sucker rod string and is inserted into the well tubing with the sucker rod string. As a complete unit, an insert pump may be inserted and pulled out of the well without removing the well tubing.
There are a number of problems that are regularly encountered during oil pumping operations. Oil that is pumped from the ground is generally impure, and includes water, gas, and solid impurities such as sand and other debris. During pumping operations, the presence of solids in the well fluids can cause major damage to the pump plunger and the barrel, as well as to other pump components, thus reducing the run cycle of the pump, reducing revenue to the pump operator, and increasing expenses. For example, during pumping operations, solids can become trapped and accumulate between the barrel and plunger, between which there is only an extremely narrow tolerance. This can create scarring and damage to the plunger and/or barrel. In particular, solids may accumulate in a direct channel in the pump plunger and/or the barrel, due to the repetitive up and down motion of the pump. With typical pump designs, solids tend to scar the plunger and/or barrel over time, which causes the solids to continually migrate and eventually completely cut through the length of the plunger. Once this occurs, the fluid seal formed between the plunger and barrel is unable to hold back fluid, causing leakage and requiring replacement of the plunger and/or barrel.
One solution to address this problem has been to provide rod rotation tools that rotate the sucker rod during pumping operations. Presently known rod rotation tools suffer from several shortcomings in various areas of the design. For example, presently known rod rotation tools are typically placed at the surface, on the above-ground pumping unit (also known as a “pumpjack”). Such tools typically rotate the complete rod string, which, in turn, will eventually rotate the plunger. This method has been successful in vertical wells, where the drill hole/wellbore is somewhat vertical to the horizon. However, problems arise when this method is used in deviated wells, as discussed further herein.
Unlike typical wellbores of the past, which are typically drilled in relatively straight vertical lines, a current drilling trend is for wellbores to be drilled vertically in part and then horizontally in part, resulting in wellbores that have some curvature or “deviation.” Such wells may commonly be referred to as “deviated” wells. When drilling deviated wells, drillers typically drill vertically for some distance (e.g. one mile), through the upper zone and down to the bedrock, and then transition to drilling horizontally. One advantage to drilling wellbores in this configuration is that the horizontal area of the well typically has many more perforations in the casing, which allows for more well fluid to enter the wellbore than with typical vertical casing wells. This, in turn, allows for more well fluid to be pumped to the surface.
There are a number of problems that may be encountered with deviated wells. Horizontal wells may typically be drilled at an angle of roughly ten to twelve degrees over roughly 1000 feet to allow for a gradual slope. This results in approximately one degree of deviation for every 100 feet. A problem that occurs when drilling such wells, particularly when they are drilled relatively fast, is that the wells are not drilled perfectly, resulting in crooked wellbores. Such wells may have many slight to extreme deviations in the drill hole, which would create a non-linear configuration. When the deviated well is completed to depth, the drill pattern is positioned horizontally to drill. The pump then must be lowered from the surface through all of the deviations of the wellbore down to the horizontal section of the well where it would be placed in service. The pump could be positioned and operated within a deviation (curve) or possibly in the horizontal area of the well. Where the pump is operated in such a non-vertical configuration, use of presently known rod rotation tools can cause the rods to bind up in the tubing, preventing rotation of the pump plunger, potentially causing damage and inefficiency, and requiring replacement of pump components.
The present invention addresses these problems encountered in prior art pumping systems, and provides other, related, advantages.